Evaluation of a top hole full return drilling system applying a concentric dual drill string and an integrated pump

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FACULTY OF SCIENCE AND TECHNOLOGY

MASTER'S THESIS

Study program/specialization:

Offshore Technology

Marine and Subsea Technology

Spring semester, 2017

Open/Confidential Author:

Inger Lise Gjeraldstveit Jonassen ………

(signature of author)

Program coordinator: Professor Arnfinn Nergaard Supervisor: Stein Erik Meinseth, Reelwell

Title of master's thesis:

EVALUATION OF A TOP HOLE FULL RETURN DRILLING SYSTEM APPLYING A CONCENTRIC DUAL DRILL STRING AND AN INTEGRATED PUMP

Credits: 30 Keywords:

Concept study

System Development Top Hole Drilling Drilling Technology Subsea Technology

Number of pages: 112

+ supplemental material/other:

-

Stavanger,14.06/2017 date/year

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ABSTRACT

This thesis evaluates the possibility for a full mud return, top hole drilling system, applying a concentric dual drill string and an integrated pump. Top holes are usually drilled without mud return, leaving the cuttings on the sea floor. Sea water with barite and other additives are employed as drilling fluid and is released to the sea when used. By employing a dual drill string and a down hole pump to lift the return to top side facilities, full return is enabled. This facilitates the use of high performance mud, which have several advantages, including primary well control before the BOP is set, improved hole stability, elimination of a pilot hole to check for shallow gas influx and extended top hole sections.

Possible solutions to obtain a complete and functioning new system have been analyzed. Based on existing technology and its current limitations, two alternative systems are developed on a conceptual level. The first system includes one integrated return pump, the second employs multiple integrated return pumps. The design base case is set to 1000 meter water depth and 500 meter deep well, of which 100 meter is drilled with a 36” drill bit, and 400 meter is drilled with a 26” drill bit. This base case covers most of the top holes drilled on the Norwegian sector. System pressure estimates are presented, and a mud level regulation solution is developed and analyzed. The mud level regulation system allows the mud level in the well to be controlled to keep the well balanced and stabilized, and to prevent mud discharges to sea floor. The level regulation solution is theoretically proved, and enables reliable regulation of the mud level in the well based on existing technology. Predictions of the system behavior are made, and the limitations of the systems are presented.

The developed systems drilling capacities are analyzed and found not capable of fulfilling the base case requirements, due to the limitations of the selected dual drill pipe. The low flow rate of the pipe limits the ROP, due to high cutting generation with large drill bit diameters. The hydraulic horsepowers at the drill bit nozzles are also too low, due to the lowered available pressure drop, low flow rate, and large drill bit. However, the available pressure drop at the drill bit nozzles are estimated to over 80 bar.

It is recommended to employ a larger dual drill pipe, with increased pressure capacity. Then the drilling capacity of the system would be comparable to other full return top hole drilling systems. The systems impact on cost and drilling parameters are discussed and found to be comparable with other innovative solutions for full return top hole drilling.

There are uncertainties of both developed systems. The uncertainties regarding the system employing only one return pump concerns the design limitations of the chosen return pump type, a progressive cavity pump. The uncertainties regarding the multiple return pump system, concerns the system behavior with several return pumps distributed throughout the drill string.

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A full return top hole drilling system employing a concentric dual drill string and an integrated pump is found feasible. But due to existing technology limitations, a mud motor is chosen to power the return pump, this demands a drill pipe with a higher capacity than what exists today, to obtain comparable drilling capacity to other top hole drilling systems. The development of an electric conducting dual drill pipe would expand the possibilities much further, and improve the overall drilling capacity of the system.

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ACKNOWLEDGEMENTS

I would like to thank Professor Arnfinn Nergaard for giving me the opportunity to write a thesis on such an interesting and relevant topic. His guidance has pushed me in the right direction during the development of the thesis.

I would also like to thank External Supervisor Stein Erik Meinseth, Senior Design Engineer at Reelwell.

He has guided, helped and supported me throughout the development of this thesis. His knowledge and practical understanding of the issues at hand has been very valuable.

I would also like to thank Harald Syse, COO at Reelwell, for his helpful opinions and good ideas on the matter.

Lastly, I would like to thank my husband and children. Thank you for your patience, understanding and help along the way. And to my Haakon and Elise, yes, I will come out and play with you now!

Thank you!

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LIST OF FIGURES

FIGURE 1PRINCIPAL LAYOUT NEW TOP HOLE DRILLING SYSTEM ... 2

FIGURE 2RISERLESS MUD RECOVERY SYSTEM ... 6

FIGURE 3REELWELL DRILLING METHOD ... 8

FIGURE 4INNER PIPE VALVE ... 8

FIGURE 5DUAL DRILL STRING,REELWELL ... 9

FIGURE 6PRINCIPAL DESCRIPTION OF SYSTEM ... 10

FIGURE 7PROGRESSIVE CAVITY PUMP,ROTOR AND STATOR ... 13

FIGURE 8ROTATION OF DRILL PIPE TO POWER RETURN PUMP ... 15

FIGURE 9MUD MOTOR TO POWER RETURN PUMP ... 16

FIGURE 10MUD SUPPLY FLOW RATE AND MUD RETURN FLOW RATE ... 17

FIGURE 11LEVEL REGULATION SOLUTION ... 18

FIGURE 12PRINCIPLE ILLUSTRATION OF THE MULTIPLE PUMP SYSTEM AND THE SINGE PUMP SYSTEM... 19

FIGURE 13THE SINGLE PUMP SYSTEM ... 22

FIGURE 14THE MULTIPLE PUMP SYSTEM ... 23

FIGURE 15TOP DRIVE ADAPTER,REELWELL ... 24

FIGURE 16DUAL DRILL STRING,REELWELL ... 24

FIGURE 17DUAL DRILL STRING CONNECTIONS,REELWELL ... 25

FIGURE 18DRILL STRING VALVE ... 30

FIGURE 19TOP HOLE LEVEL TANK ... 31

FIGURE 20FLOW CONTROL UNIT,REELWELL ... 32

FIGURE 21ELEVATION OF RETURN PUMP AND INLET CONDUITS ... 37

FIGURE 22GEL STRENGTH IN CALIFORNIAN BENTONITES ... 42

FIGURE 23GEL STRENGTH IN CALIFORNIAN BENTONITES ... 42

FIGURE 24PRESSURE DISTRIBUTION SINGLE PUMP SYSTEM ... 44

FIGURE 27EXAMPLE PRESSURE DISTRIBUTION,SINGLE PUMP SYSTEM ... 50

FIGURE 28START-UP PRESSURE PEAK GRAPH ... 52

FIGURE 29PRESSURE DISTRIBUTION,THE MULTIPLE PUMP SYSTEM WITH FOUR MOTOR-PUMP SETS ... 53

FIGURE 30PRESSURE DISTRIBUTION MULTIPLE PUMP SYSTEM ... 56

FIGURE 31PRESSURE GRAPH DISTRIBUTION MULTIPLE PUMP SYSTEM ... 56

FIGURE 32PRESSURE DISTRIBUTION BASE CASE SINGLE PUMP SYSTEM ... 57

FIGURE 33PRESSURE DISTRIBUTION BASE CASE MULTIPLE PUMP SYSTEM ... 58

FIGURE 34NOVPC PUMP,EPSILON E1BD ... 60

FIGURE 35NOV MUD MOTOR DATA SHEET ... 60

FIGURE 36PUMP AND MOTOR FLOW COMPARISON ... 63

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FIGURE 37MOTOR AND PUMP FLOW ESTIMATION OF DRILLING SCENARIO 1 ... 64

FIGURE 38MOTOR AND PUMP FLOW ESTIMATE OF DRILLING SCENARIO 2 ... 65

FIGURE 39VOLUME FLOWS DURING DRILLING ... 66

FIGURE 41LEVEL REGULATION WITH VARIABLE ROP ... 68

FIGURE 42MOTOR CONFIGURATION, INCREASING LOBE NUMBER ... 69

FIGURE 43COMPARISON PUMP AND MOTOR POWER ... 71

FIGURE 44COMPARISON PUMP AND MOTOR TORQUE ... 71

FIGURE 45MOTOR BYPASS THROUGH ROTOR ... 72

FIGURE 46NOV NOZZLE SIZE SELECTION ... 73

FIGURE 47BIT DIFFERENTIAL PRESSURE WITH VARIABLE FLOW RATES AND CUTTING CONTENTS ... 82

FIGURE 48MAXIMUM AVERAGE ROP ... 83

FIGURE 49REQUIRED DIFFERENTIAL PRESSURE OVER RETURN PUMP WITH INCREASING WATER DEPTH AND WELL LENGTH ... 84

FIGURE 50REQUIRED DIFFERENTIAL PRESSURE OVER MOTOR WITH INCREASING WATER DEPTH... 84

FIGURE 51REQUIRED PRESSURE INCREASE BY RETURN PUMPS WITH INCREASING WATER DEPTH AND WELL LENGTH ... 85

FIGURE 52REQUIRED MOTOR DIFFERENTIAL PRESSURE WITH INCREASING WATER DEPTH AND WELL LENGTH ... 86

FIGURE 53CAN-DUCTOR,NEODRILL AS ... 90

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LIST OF TABLES

TABLE 1ABBREVATIONS ... XIII TABLE 2NOMENCLATURE ... XV

TABLE 3RMR KEY COMPONENTS ... 6

TABLE 4SYSTEM REQUIREMENTS ... 10

TABLE 5LEVEL REGULATION PRINCIPLE ILLUSTRATION EXAMPLE ... 19

TABLE 6ALUMINUM DRILL PIPE 57/8 ... 25

TABLE 7COMPARISON OF RETURN FLUID VELOCITY WITH A 26" DRILL BIT ... 26

TABLE 8REELWELL DRILLING METHOD,SAUDI ARABIA,ABHADRIA ... 27

TABLE 9REQUIRED DIFFERENTIAL PRESSURE OVER DRILL BIT TO OBTAIN HSI=0,85 ... 27

TABLE 10MAXIMUM ROP AS A FUNCTION OF MAXIMUM CUTTING CONTENTS LIMIT OF DDS ... 29

TABLE 11SELECTED DRILLING SCENARIO PARAMETERS ... 33

TABLE 12ASSUMPTIONS MADE WITH REGARDS TO ESTIMATION OF PRESSURE DISTRIBUTION ... 35

TABLE 14SURFACE CONNECTION PRESSURE LOSS ... 40

TABLE 15EXAMPLE PRESSURE DISTRIBUTION, INPUT VALUES ... 49

TABLE 16EXAMPLE PRESSURE DISTRIBUTION SINGLE PUMP SYSTEM ... 50

TABLE 17EXAMPLE PRESSURE DISTRIBUTION, INPUT VALUES ... 54

TABLE 18EXAMPLE PRESSURE ESTIMATION MULTIPLE PUMP SYSTEM ... 55

TABLE 19EXAMPLE OF WELL SECTION DRILLED WITH RPM AT 152 AND ROP AT 40 M/H ... 67

TABLE 20LEVEL INCREASE WITH PRESSURE OVER THE RETURN PUMP. ... 68

TABLE 22POWER AND TORQUE DISTRIBUTION ... 71

TABLE 23DIFFERENTIAL PRESSURE DRILL BIT NOZZLES WITH INCREASING WATER DEPTH AND WELL LENGTH ... 80

TABLE 24HSI OF 26" DRILL BIT WITH INCREASING WATER DEPTH AND WELL LENGTH ... 81

TABLE 25COMPARISON OF DEVELOPED SYSTEMS TO RMR ... 93

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ABBREVATIONS:

BOP Blow out preventer

BHA Bottom hole assembly

CTS Cutting Transportation System

DDS Dual Drill String

DH Down Hole

DSV Drill String Valve

HSI Hydraulic power at drill bit [hp/in²]

MRL Mud Return Line

MRR Mud Recovery without a Riser

MWD Measure While Drilling

OTC Office and Tool Container

PCC Power and Control Container

PGB Permanent Guide Base

RCD Rotating control device

RDM Reelwell Drilling Method

RMR Riserless mud recovery

ROP Rate of Penetration

RPM Rotations per minute

SOM Suction Module

SPM Subsea Pump Module

UW Umbilical Winch

TDA Top Drive Adapter

TVD True vertical Depth

Table 1 Abbrevations

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NOMENCLATURE

Symbol Explanation unit

∆𝑷_𝒇𝑨 Frictional pressure loss in annulus bar

∆𝑷𝒇𝑰𝑷 Frictional pressure loss in inner pipe Bar

∆𝑷_𝒇𝑷𝑩 Frictional pressure loss in pipe body Bar

∆𝑷_𝒇𝑻𝑱 Frictional pressure loss in tool joint Bar

∆𝑷𝒉 Hydraulic differential pressure bar

𝑪 Constant value

𝑪𝑺𝑪 Constant value for calculation of pressure loss in surface connections

𝑫_𝒊𝑰𝑷 Inner diameter of inner pipe m

𝑫𝒊𝑷𝑩 Inner diameter of outer pipe m

𝑫_𝒊𝑻𝑱 Inner diameter Tool joints m

𝑫_𝒐𝑰𝑷 Outer diameter of inner pipe m

𝑫𝒐𝑰𝑷𝑪 Outer diameter of inner pipe connections m

𝑫_𝒐𝑷𝑩 Outer diameter of outer pipe m

𝒅𝒑_𝒇 𝒅𝑳

Pressure gradient gel strength kPa/m

𝒈 Specific gravity m/s²

𝒉_{𝑩𝑯𝑨+𝑴} Height of motor and BHA m

𝒉𝑫𝑭 Drill floor height from sea level m

𝒉_𝑺𝑾 Sea water depth m

𝒉𝑾 TVD well m

𝑷_{𝑴 𝒊𝒏} Power input to motor kW

𝑷𝑴 𝒐𝒖𝒕 Power out from motor kW

𝑷_{𝑷 𝒊𝒏} Power input to pump kW

𝑷𝑷 𝒐𝒖𝒕 Power output from pump kW

𝑳 Length m

𝑳_𝑷 Length pipe m

𝑳_𝑷𝑩 Length pipe body m

𝑳_𝑻𝑱 Length tool joint m

𝝆_𝑪 Average density Cuttings Kg/m³

𝝆_𝑴 Average density mud in annulus Kg/m³

𝝆_𝑷 Average density mud in return pipe Kg/m³

𝝆_𝑺𝑪 Average density static column Kg/m³

𝝆_𝑺𝑾 Sea water density Kg/m³

𝝁_𝑷 Viscosity in inner pipe cP

𝝁_𝑴 Viscosity in annulus cP

𝑪𝑴𝑵 Magic number

𝑷_𝑩𝑯𝑨 Pressure loss in BHA bar

𝑷𝑩𝑯𝑨 𝒖/𝒔 𝒏𝒐𝒛𝒛𝒍𝒆𝒔 Pressure loss in BHA upstream nozzles bar

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𝑷_𝒇𝑩𝑯 Pressure due to friction in bottom hole Bar

𝑷𝒉𝑯𝑺𝑰 Hydraulic power at bit per square diameter HP/in²

𝑷_{𝑷𝒐𝒖𝒕} Pump outlet pressure bar

𝑷𝒇𝑰𝑷 Frictional pressure loss in inner pipe Bar

𝑷_𝒉 Hydraulic pressure bar

𝑷_𝒉𝑷 Hydraulic pressure of pump height bar

𝑷_𝒉𝑰𝑷 Hydraulic pressure in inner pipe bar

𝑷𝒉𝑺𝑪 Hydraulic pressure of static column Bar

𝑷_𝒉𝑺𝑾 Hydraulic pressure of sea water Bar

𝑷𝑴 Pressure drop in motor Bar

𝑷_𝒎𝒊𝒏 Minimum return pressure to topside bar

𝑷𝑷 Pressure increase by pump bar

𝑷_𝑻𝑺 Top side return pressure bar

𝑷𝒇𝑺𝑬 Pressure drop in surface equipment bar

𝑸_𝑩𝑷 Flow rate motor bypass lpm

𝑸_𝑪 Volume flow rate of cuttings lpm

𝑸𝒇𝒐𝒓𝒎𝒂𝒕𝒊𝒐𝒏 𝒇𝒍𝒖𝒊𝒅 Inflow from formation lpm

𝑸_𝑴 Flow rate motor lpm

𝑸𝑨 Flow rate annulus lpm

𝑸_𝑷 Flow rate return pump lpm

𝑸𝒔𝒍𝒊𝒑 Slip flow through pump lpm

𝒓_𝒘 Internal radius in

𝝉_𝒈 Gel strength Lb/ft²

𝑻_{𝑴𝒐𝒖𝒕} Motor output torque Nm

𝑻_𝑷𝒊𝒏 Pump input torque Nm

Table 2 Nomenclature

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1 INTRODUCTION 1.1 Background

Today’s top hole drilling is usually accomplished by “drill and dump”. This normally implies drilling with a low-cost drilling fluid, which is flushed out of the hole together with drill cuttings to remain on the sea floor. After the top holes are drilled and casings are set and cemented in place, the blow out preventer, BOP and drilling riser is run. A full return drilling system is now established, allowing high performing mud to be employed. The “drill and dump” method has several disadvantages; the environment is affected by the discharges, and the alternative low-cost, low-toxicity drilling fluids may not have the necessary quality for drilling in challenging geological conditions. This leads to higher risks for drilling interruptions and safety hazards. However, there are several innovative drilling systems with full return of drilling fluid, during top hole drilling. One of the most credited systems within this topic is the “Riserless Mud Recovery Technology”, RMR, by Enhanced Drilling. IKM’s “Mud Recovery without a Riser” system, MRR, has similar characteristics. However, both RMR and MRR have their weaknesses. One weakness is the dependence upon installation and hook-up of several modules topside and subsea.

It is important to further develop top hole drilling to avoid drill and dump, to optimize drilling parameters, to extend casing setting depth, to enable the use of high performing mud during top hole drilling and to study the possibility for a simplified method of full return top hole drilling. Reelwell AS and professor Arnfinn Nergaard desired a master thesis on this subject, evaluation of the possibility for a full return top hole drilling system applying Reelwell’s dual drill string together with an integrated pump. The principal layout of the system would look like the following illustration. The illustration shows the dual drill string with supply mud in the annulus, and return mud and cuttings in the inner pipe. A pump lifts the returning fluid to top side facilities, to avoid it flowing out of the well onto the sea floor.

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2 Water depth

Mud level in well

P

Mud supply

Mud return

Dual drill string

Bottom hole assembly

Figure 1 Principal layout new top hole drilling system

1.2 Objective

The objective of the thesis is to evaluate the possibility for a full return top hole drilling system, applying a concentric dual drill string with an integrated pump. Intermediate objectives include to evaluate possible system components, and solutions to obtain a functional system. This includes selection of:

• Pump type

• Pump motor type

• Solution for regulation of the mud level in the well

Practical solutions, for the system parameters above, are to be considered and a new system to be developed.

1.3 Scope of work

To evaluate the possibility of a full return top hole drilling system, as described above, possible solutions to obtain a functioning new system has been analyzed. Based on existing technology and its current limitations, two solutions for a full return top hole drilling system has been further evaluated

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and analyzed. Technical solutions to complete the system, with regards to avoiding mud emission to the sea floor, has been developed and analyzed. The limitations of the developed systems are discussed, and compared to existing full return top hole drilling systems. The limitations of the developed systems are also evaluated in comparison to other possible solutions for full return top hole drilling systems, based on futuristic technology. Such futuristic technology includes an electrical cabled dual drill string and remotely operated equipment.

Focus on HSE, schedule impact and cost is kept during the development of the new system. The development is kept at a conceptual stage, no testing or detailed design is performed. An overall evaluation on the systems top hole drilling capacity is performed after the system evaluation. Sources of error and uncertainties are discussed.

The thesis will not elaborate upon geological drilling parameters, only brief discussions are made.

1.4 Structure of the thesis

The thesis is divided into nine main chapters:

INTRODUCTION

The thesis background, objective, scope of work and the thesis structure is described to give an introduction of the thesis.

EXISTING TECHNOLOGY

Existing technology and innovative solutions for full return top hole drilling are discussed. Reelwelll AS and their Reelwell Drilling Method is described. Reelwells dual drill string, employed in the thesis is introduced.

DEVELOPMENT OF A NEW FULL RETURN TOP HOLE DRILLING SYSTEM

The first section describes the problem to be solved by the thesis, to clarify the problem to the reader.

The second section describes the strategy for system development and the requirements for a new top hole drilling system with full return. The first decisions to obtain a principal system design are made. A short evaluation and selection of solution to enable mud level regulation of the well is presented.

The components of the new system are described, and short analyzes are performed on the dual drill pipe.

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ESTIMATION OF PRESSURE DISTRIBUTION WITHIN THE SYSTEMS

The pressure distribution within the systems are estimated to find the limitations of the system, and to be able to select a suitable pump and motor. The estimations are necessary to evaluate a developed principle for the level regulation.

LEVEL REGULATION PRINCIPLE AND MOTOR-PUMP FUNCTIONING

In this chapter, a technological solution to enable the level regulation of the well is described, analyzed and evaluated. The principle reflects on the estimations done in the previous chapter. A discussion of the principle highlights possible errors of the principle.

ANALYSIS OF SYSTEM BEHAVIOUR

This chapter evaluates the behaviors and responses of the systems in various drilling scenarios. The reader gets more familiar with the system functioning.

Uncertainties regarding the design of the system are discussed.

RESULTS

The systems drilling capacity is presented. Pump requirements for the systems are presented.

Uncertainties are highlighted.

DISCUSSION

The system design and limitations are discussed.

The possibility for a full return top hole drilling system applying a concentric dual drill string with an integrated pump is discussed with regards to futuristic technology. Learning points are described.

CONCLUSION

The conclusion of the thesis is presented.

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2 EXISTING TECHNOLOGY

2.1 Conventional top hole drilling

There are three ways of establishing the top holes: The widest casing, usually 30”, can be drilled and cemented, drilled and hammered down or just hammered into place. It is not uncommon to employ both drilling, or so called “wash down”, together with hammering. The use of different subsea guide frames depends on which vessel the well is drilled from. When drilling from a jack-up or a floating rig it is normal to drill through a template, with several slots, or a satellite well template with only one slot.

Since the accident on West Vanguard at Haltenbanken in 1985 it has become common to drill the top holes without the use of a riser, to prevent uncontrolled gas to enter the rigs drilling area. Shallow gas pockets have been expected to be of a minor size, allowing the gas to disperse with water depths over 100 meters, when drilling an 18 5/8” pilot hole. Drilling the pilot hole is however, avoided with the use of RMR. This saves a day or so in rig time, which is of significant expense.

With expansion of drilling into more environmentally fragile areas, drilling methods are under discussion. Seafloor corals and other ecologically important organisms cause concern with dumping of the top hole cuttings. To enable drilling of top holes without dumping expensive and environmentally damaging high performing drilling fluid, several innovative technologies have been patented, tested and taken in use.

Some areas are prone to top hole instability, shallow gas, “gumbo” sands, weak zones and so on, which may only be safely and economically drilled with high performing mud. An example is Canadian Natural Resources Ltd.’s, CNR’s, drilling in the Northern North Sea, where four out of eight spudded wells were abandoned due to stuck tubing or casing.[1]

2.2 Full return top hole drilling, RMR and MRR

Riserless mud recovery, RMR, by Enhanced Drilling, is, as mentioned earlier, a system allowing full mud return without the use of a riser. RMR was developed by AGR for BP Exploration in 2003 and was evolved from the existing Cutting Transportation System, CTS. CTS is a subsea cutting transportation system, including pumps and hoses, moving the cuttings away from the well template.[1] Since then, RMR has been used to drill over 200 wells all around the world and has several merits from respected companies, such as BP, CNR and INPEX. [1-3]A standard RMR system setup is shown below in Figure 2, Table 3 describes the system components. The figure is taken from an article called "Safe and Efficient Tophole Drilling using Riserless Mud Recovery and Managed Pressure Cementing," written by R. Stave, P. Nordas, B. Fossli, and C. French, on the RMR system. [4]

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Figure 2 Riserless Mud Recovery System

RMR Key components 1 Suction Module, SMO 2 Subsea Pump Module, SPM

3 Umbilical and Umbilical Winch, UW 4 Office and Tool Container, OTC 5 Power and Control Container, PCC 6 Mud Return Line, MRL

Table 3 RMR key components

[4]

Enhanced Drilling claims drilling top holes with RMR will enable:

• “Primary well control before BOP riser is installed

• Ability to check for shallow-hazard influx without a pilot hole

• Improved hole stability

• Deeper surface casing

• Fewer casing strings

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• Top-hole mud log data and cuttings

• No cement top-up jobs required

• Zero discharge at seabed”[5]

Safety advantages Enhanced Drilling claims RMR will benefit are:

• “Safe identification of gas

• Better conductor/Xmas tree stability

• Mud volume control in surface hole

• Fast gain/loss indication

• Real-time visual monitoring of the well

• No smothering of sea bed by cuttings

• Lower risk of undermining well template”

From Enhanced drilling, RMR, web page[5]

A competitor to RMR, with a similar system is IKM’s “Mud Return without a Riser” system, the MRR system. The MRR system has principally the same build-up and functioning as the RMR system. The first application for IKM’s MRR system was for Shell on the Malikai project, offshore Sabah, Malaysia in 2014. MRR has also been contracted to AkerBP in 2016, and was to be installed on Transocean Arctic semi-submersible rig early 2017, for drilling on Alvheim.[6, 7]

2.2.1 RMR and MRR Disadvantages Weaknesses of the RMR and MRR systems are:

• The deployment of equipment through the splash zone has caused delays in operations.

One such case was the INPEX drilling through soft Grebe sands in the Browse Basin in 2008.[2]

• Currents and poor visibility may cause delays and problems with the subsea hook-ups of umbilical and the flow lines/hoses.

• The dependence on ROV is also considered a weakness to the two systems.

2.3 Reelwell AS and Reelwell Drilling Method

Reelwell AS is an innovative technology company in Stavanger founded in 2004 by Ola M. Vestavik.

The company delivers pioneering technology to the oil and gas drilling industry, and has won the DNB Innovation Prize and ONS Innovator Award and five Spotlight on new technology awards.[8] Two of the awards concerns the “Reelwell Drilling Method”, RDM.

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RDM, use a Dual Drill String, DDS, with a separate inner pipe leading the return fluid to topside facilities.

The DDS connects to the top drive with an adapter, and can be directly connected to any standard bottom hole assembly, BHA. The return drill fluid is led through entrance ports and an inner pipe valve directly above the BHA. The inner pipe valve closes during pipe connections, and isolated of the return pipe from the well. Since the inlet to the inner pipe is set above the BHA, the rest of the annulus, between the DDS and the formation remain in near static conditions. This has several positive effects on drilling parameters such as hole cleaning.[9] Figure 3 and Figure 4 below are taken from a RDM Technology flyer, and shows the RDM system and the Inner Pipe Valve[9]. The Remaining components will be further discussed as they will be a part of the systems developed in the thesis.

Figure 3 Reelwell Drilling Method

Figure 4 Inner Pipe Valve

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3 DEVELOPMENT OF A NEW FULL RETURN TOP HOLE DRILLING SYSTEM

3.1 Principal description of system

The concept of the drilling system is to apply a concentric dual drill string together with an integrated return pump. The dual drill string, DDS, shown below, is taken from a technology flyer on RDM[9]. The DDS has the returning conduit in the inner pipe. The supply fluid flows through the annulus of the dual drill pipe. The dual drill string is handled like a standard drill pipe, and the connections are made by threading the outer pipe, as with a normal drill pipe.

Figure 5 Dual Drill String, Reelwell

The inner pipe allows the return fluid to be lifted by an integrated pump from the bottom of the well, to top side facilities. Without the pump, the mud and cuttings would flow up the well and onto the sea floor, as with conventional top hole drilling. To obtain a full return system, the mud level in the well needs to be controlled. The pump type, motor type and solution for regulating the mud level in the well must be obtained. The principle layout of the system is illustrated below.

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M

Water depth

Mud level in well

P

Mud supply

Mud return

Dual drill string

Bottom hole assembly

Figure 6 Principal description of system

3.2 Strategy for system development and thesis writing

The strategy for the development of the system has been to evaluate all functional possibilities with regards to the available technological solutions to achieve a complete system. Options with remotely controlled equipment, such as radio-controlled valves, have been excluded.

Some system requirement, set as a base case, are listed in the table below.

System requirements:

Water depth 1000 meter

Well length(TVD) 100 meter 36”, 400 meter 26”

Not numbered requirements:

Good safety characteristics with regards to unexpected shallow gas kicks, drilling monitoring and control

Simple deployment Good hole stability Good hole cleaning

Table 4 System requirements

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11 System variables to be set are:

• One or Multiple pumps

• Pump type

• Pump position in the drill string

• Pump power source

• DDS size and capacity

• Control of mud level in the well

After the system has been developed it is analyzed and evaluated. The system design is discussed. The limitations for the developed systems are discussed and compared to limitations expected for a system developed with futuristic technology. Such futuristic technology includes a cabled dual drill string, or a larger dual drill string.

3.3 Evaluation of the Return Pump

One or several return pumps accelerates the returning drilling fluid and cuttings through the inner pipe to top side. There are several demanding characteristics needed for the return pump/s to function as intended. It needs to:

• tolerate solids and abrasive fluids

• have a small diameter to fit inside hole

• have a suitable flow and pressure range

A variety of pumps have been evaluated and the most suitable pump types are discussed in the following sections regarding selection of pump type. Pump flow rate capacity is dictated by the DDS maximum flow range (1200 lpm).

3.3.1 Jet Pump

A jet pump utilizes high pressure energy in a fluid converted into high velocity in a nozzle. A following low pressure zone allows new fluid to be drawn in and accelerated through the pump throat. The idea is to utilize high pressure in the fluid flowing to the well and conducting some of the flow through the jet nozzle. The possibility for utilizing a jet pump was discussed in a report Reelwell made, called the

“Athabasca pump feasibility” report. In this report Reelwell evaluated the possibility for a downhole, DH, pump to lower the backpressure while production drilling in a reservoir uncappable of detaining pressure from topside to circulate. The requirements for the Athabasca drilling were low compared with the requirements for conventional top hole drilling, with an expected TVD of up to 445 meter.

The report stated that to make a DH jet pump work the required pressure from surface would have to

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be 755 bar, and the necessary return flow would have to be around 2126 liter per minute. Both specifications are higher than the upper limits and the jet pump option is concluded not feasible. [10]

3.3.2 Centrifugal pump

Centrifugal pumps are the most popular pump type in the oil and gas industry. It is a versatile pump type, which can be adapted to many flow and pressure ranges, and can be built to tolerate solids and abrasive fluids. Assembled together with an electrical motor the centrifugal pump could be a viable option, had it not been for the required size to obtain the necessary flow capacity and power demand.

The centrifugal pump is disregarded as a viable option due to size.

3.3.3 Turbine pump

Vertical turbine pumps have similar operational functionality to the centrifugal pumps. Impellers or fans thrust the fluid upward by employing high fan velocities. Vertical turbine pumps can be configured with several stages to obtain high pressure and flow capacities, but the solids tolerance is of concern.

The turbine pump could be a feasible option if the solids tolerance was high enough. However, due to the uncertainties regarding solids tolerance the turbine pump is disregarded.

3.3.4 Piston pump

It has become increasingly popular to employ piston pumps for fluids containing solids. However, this is not a suitable pump type for DH applications due to the size constriction.

3.3.5 Progressive Cavity Pump

Progressive Cavity pumps, PC pumps, are long and slender and holds the required size. They are tough pumps especially suited for multiphase fluids with high solids contents. PC pumps have a helical working rotor inside a helical stator. The lobe number is always one higher for the stator and cavities between the rotor and stator moves axially as the rotor rotates. The number of stages dictate the maximal pressure capacity of the pump, along with the fit between the stator and rotor. The tighter the fit, the more friction and wear of the pump, but less slip back through the pump, and therefore a higher discharge pressure capacity. The following illustration shows the rotor and stator of a PC pump, the picture is taken from a National Oilwell Varco’s web page on PC pumps[11].

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Figure 7 Progressive Cavity Pump, Rotor and Stator

PC pumps can be designed to accommodate high flow rates or discharge pressures. However, the pressure range of these pumps become restricted with increasing flow rates.

3.4 Conclusion: Pump selection

The turbine pump and the PC pump are considered to be the best options. Progressive cavity pump has been selected as the superior pump alternative due to its solids tolerance.

3.5 Evaluation of Return Pump Power Source

The return pump power source dictates the overall system design and needs to be one of the first decision to be made.

At first glance, there are several ways to power the Return pump;

• Electricity

• Rotation of drill pipe

• Hydraulic mud motor 3.5.1 Electricity

Employing electricity to power the return pump would simplify regulation of mud level in the well, and open for a range of different pump types and size options. A high performing electric conductor in the DDS would allow high power to be transported to the return pump, leading to good system drilling capacity. However, currently there are no drill pipes with a leading conductor available, nonetheless concentric dual drill strings. Therefore, the option of electricity to power the return pump is disregarded. This would be an interesting option if a DDS with included power cable was invented.

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It should be mentioned that Reelwell conducted an experiment in which the DDS was upgraded to function as a conductor to DH instruments. This allowed real-time monitoring without the loss of mud- signals with circulation breaks. The outer and inner pipes where isolated from each other and thereby used as positive and negative source, while drilling with a non-conductive mud.[12] However, the return pump/s would require high voltage and amperage, and the conducted experiment settings is therefore considered not feasible for the powering of the return pump/s.

3.5.2 Rotation of the drill pipe

There are large amounts of energy available in the rotation of the drill pipe. If the pump was driven by rotation of the pipe, it would be easy to control and regulate the pump output or stop and start the pump as desired. However, there are several challenging obstacles in the way:

The bit would need to be powered by a mud motor alone or rotation would need to power both sources. If the rotation was to be used only for the return pump, some kind of restraint to hold back the rotation and generate torque would be necessary, see figure below. With a drill bit mud motor the bit acts as the restraint, grinding against the formation. If the rotation was to be used to power both the bit and the return pump, some kind of energy transfer device would have to be invented to conduct torque from the bit to the pump. But the regulation of the pump would be advanced, as the pump and bit might need independent regulation. Excessive bit wear may be a cause of concern. Vibrations, and other factors would need to be addressed by a damping device. Another cause of concern is that rotation of the pipe is used by drillers in various scenarios, for other reasons than ROP.

This power source is considered to be unpractical, but may be possible with extensive analyses and development. The evaluation of the feasibility of this power source is considered beyond the scope of this thesis.

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Gear box

P

Rotational restraint Return pump

Gear Box

BHA

DDS

Figure 8 Rotation of drill pipe to power return pump

3.5.3 Hydraulic power – mud motor

DH mud motors are widely employed in petroleum drilling to rotate the drill bit during directional drilling. Therefore, the science of mud motors has advanced in recent years and there is a broad selection of high performing mud motors available on the market. Mud motors come in a variety of sizes and with varying flow and pressure capacities, and mechanical power and torque output.

However, the coupling of a mud motor to a return pump would require careful considerations regarding pump and motor flow rates and power and torque generation and absorption. Measures must be taken to enable regulation of the mud level in the well, since both motor and pump power requirements are dependent upon the flow rate.

The employment of mud motors also cause concern with regards to the available hydraulic pressure to be subtracted from the rest of the system. The option of large mud motors to power the bit is eliminated, this could affect the ROP and the possibility for directional drilling of deep top holes. The

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pressure distribution in the proposed systems are analyzed in detail in later chapters and the mud motor requirements are set as a function of pressure drop, flow rate, and required power output.

P M

To top side To bottom hole assembly

Motor Pump

Figure 9 Mud Motor to Power Return Pump

3.6 Discussion and Conclusion: Return pump power source

The best and simplest option appear to be a cabled DDS with an electric motor to power the pump, however, this is not yet an option. The rotation of drill pipe, could strictly operational be a simple solution. But the mechanical solution to enable pump rotation from drill string rotation is complex, and is therefore disregarded.

The only solution available, without extensive new design, is the employment of a mud motor to power the return pump. This may eliminate the possibility to use a mud motor to power the bit in addition to the mud motor powering the return pump. The reason for this is the limited available pressure in the system, due to the employment of a mud motor to power the pump, pressure loss in the pipe, required pressure drop in the drill bit and pressure limitations of the equipment. However, the top holes can be drilled without a mud motor powering the bit. The operational window of the systems is also limited due to high required pressure drop in the motors to power the return pumps.

The pump and motor would have to be designed and paired together with regards to torque, power, flow and differential pressures, and the mud level in the well also needs to be accounted for.

3.7 Evaluation of solutions to control the mud level in the well

The mud level in the well needs to be controlled to keep the drilled hole stabilized and to avoid mud spills onto the sea bed. Since the chosen power source of the return pump is a mud motor, the available solutions to control the mud level in the well becomes more complicated. The return pump is assumed to be directly coupled to the mud motor, thus the motor and the pump will rotate with the same speed.

This leaves only the mud supply flow rate to adjust the RPM of the pump and motor, and thereby the return pump flow rate. The circulatory system in the well can be considered to be two independent systems, the supply system, and the return system. The only connection between the two systems is the shaft between the mud motor and the return pump. The flow rates of the supply system and return

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system are not equal. It is necessary to control the flow rates in both systems, however, this is complicated, because the only way of controlling the return pump, is by adjusting the flow rate of the mud motor.

Two solutions to obtain level regulation is enabled by choosing a pump with a higher displacement, than the motor. Then when the motor and pump rotates, the flow through the motor will always be lower than the flow rate through the pump.

The two solutions to obtain regulation capability:

• Employing a return pump with a higher displacement, than the mud motor, continuously draining the mud level in the well during circulation. And combining the draining with a filling line from topside. See right side of figure below.

• Employing a return pump with a higher displacement, than the mud motor, in combination with a motor bypass conduit. Without the motor bypass conduit, the higher displacement of the return pump would imply continuously drainage of the mud level in the well. With high RPM, the different displacements would cause a larger difference in flow rates through the motor and return pump. This would mean faster mud level decrease rate with high RPM, and lower decrease rate with low RPM. When including a motor bypass conduit to the design, the supply flow rate is increased without affecting the RPM of the motor and return pump. If the bypass flow rate is sized correctly then the supply flow rate can be balanced with the return flow rate, such that well drainage is enabled at high RPM and well fillage is enabled at low RPM. The flow rates are shown in the graph below. A following example is presented to clarify the mud level regulation solution.

Figure 10 Mud supply flow rate and mud return flow rate 0

200 400 600 800 1000 1200 1400 1600 1800

75 100 125 150 175 200 225 250 275

Flow [lpm]

RPM

Level regulation: supply and return flow rates

Pump Motor Motor + bypass Flow rate balance RPM

Level decrease Level increase

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M Return Supply

P Bypass

Shaft

M Return Supply

P Shaft

BHA BHA

Filling line

Figure 11 Level Regulation Solution

As explained above, the level regulation principle is made possible by allowing the driller to adjust the flow rate from the topside mud pumps to obtain variable RPM of the mud motors and return pumps.

Keeping in mind that the mud motors and return pumps have the same RPM and selecting a return pump with a higher displacement, creates a difference in flow rate into and out of the well. However, with a constant higher flow out of the well than into the well, the well would be drained continuously.

Therefore, a bypass flow passing the motor, without entering it, will increase the flow into the well without changing the RPM of the motor and pump. This enables both well drainage at high RPM, and high flow rates, and well filling with low RPM, and low flow rates.

The level control solution with the motor bypass flow is employed.

Example to illustrate level regulation Off bottom circulation. Stable conditions.

Motor and pump speed 150 rpm

Motor displacement per revolution 6 l/rev

Pump displacement 8 l/rev

Bypass flow rate 200 lpm

Motor flow rate 900 lpm

Pump flow rate 1200 lpm

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Difference in flow in and out of well (1200 − 900 − 200)𝑙𝑝𝑚 = 100𝑙𝑝𝑚 The mud level in the well is increasing with 100 lpm.

Table 5 Level regulation principle illustration example

3.8 Presentation of The Single Pump System and The Multiple Pump System

Now that the pump type and the power source for the return pump has been selected and the solution to control the mud level in the well has been set, the overall system design has been set. Two systems have been selected, after careful considerations, for further evaluation. They are called The Single Pump System, and The Multiple Pump System. The two systems are introduced and described in the following sections. A principal illustration, Figure 12, below shows the build-up of the two alternative systems.

M

BHA M P

M

BHA

M P

Single Pump System Multiple Pump System

P P

Flow Control

Unit

Top Drive Adapter Flow

Control Unit

Top Drive Adapter

Mud Motor Return Pump

Bottom Hole Assembly Top Hole Level Tank

Return Pump Return Pump Return Pump

Mud Motor Mud Motor Mud Motor Top Hole Level Tank

Bottom Hole Assembly

DDS DDS

Figure 12 Principle illustration of The Multiple Pump System and The Singe Pump System

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The DDS in conjunction with a return pump and return pump motor are the key components in the systems. In the multiple pump systems, one return pump is replaced by a series of pump-motor sets positioned up the DDS. The goal is to reduce the required pressure capacity of the pumps. The number of pump-motor sets in the multiple pump system can be adjusted to the requirements of the top hole, and the desired pressure capacity of the return pumps. The “Top Hole Level Tank”, THLT, is also a key component to the systems, permitting monitoring of the mud level in the well. Other equipment necessary to complete the systems are:

• Top drive adapter, TDA

• Drill String Valve, DSV

• Check Valve

• Flow Control Unit, FCU

• Operation Station

These system components will be discussed in the following sections, after the principal system functions have been described.

3.9 The Single Pump System Operational Principle

The return pump lifts the drill fluids from the well to topside facilities to create a full recovery system.

As described earlier, the return pump is powered by an associated mud motor.

During circulation, the drill fluid is pumped to the well from the topside mud pumps through the annulus of the DDS. The fluid flows through a mud motor powering the associated return pump, before entering a standard BHA. The remaining overpressure in the pipe is consumed in the bit nozzles.

Outside the BHA, in the bottom of the hole, the drill fluid flushes and carries cuttings to the return pump inlet. The mixture is flowing through the return pump inlet channels, to the inner pipe. There, the cuttings and mud are pumped up the to the Top Drive Adapter, TDA. The Flow Control Unit, FCU, including flowmeters, isolation valves and choke valves, is then the only remaining equipment before the standard rig equipment. See Figure 13 on the next page.

After spud in, the mud level in the hole is monitored by transmitters in the Top Hole Level Tank, standing in the top of the hole. Regulation of the mud level in the well is, as briefly described earlier, enabled by using different flow capacities between the mud motor and the return pump, and a bypass flow passing the motor. See Figure 13 below. Keeping in mind that the RPM of the motor and pump are the same, and applying a pump with a higher displacement per revolution than the motor, the flow rate will be constantly higher through the pump, than the motor. With high RPM, the flow through the pump is significantly larger than the flow through the motor, with low RPM the flow rate through the

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pump is still larger but closer to the flow through the motor. By adding the flow through the bypass, the total flow into the well is higher than out of the well with low RPM. With high RPM, the flow rate out of the well is larger than into the well. The RPM of the motor and pump is varied by adjusting the top side flow rate. The Operation Station, OS, in the drillers cabin allows the driller to operate the mud level by changing the flow rate of the top side mud pumps.

As the Figure 13 below shows, the bypass flow is passing the motor in the center of the rotor of the PC pump. The bypass is small and is equipped with a nozzle to restrict the flow rate through the conduit.

An additional opportunity to regulate the mud level in the well is enabled by a topside choke valve in the return line. Restricting the return flow causes pressure build-up and the slip through the return pump is increased, end the flow rate out of the well is lowered.